Data processing system for mapping fracture length using downhole ground penetrating radar

ABSTRACT

Ground penetrating radar (GPR) measurements from a downhole well tool in a wellbore are obtained to identify length of fractures adjacent the wellbore. A ground penetrating radar transmitter of the downhole tool emits an electromagnetic pulse. The electromagnetic wave of the ground penetrating radar is diffracted on encountering an end or tip of a fracture, which acts as a secondary source. The diffracted signal is then collected by downhole receiver(s) of the downhole tool. Length of the fracture is determined based on the time of travel of the electromagnetic wave from its emission until its collection as a diffracted signal by the downhole receiver(s).

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of, and claims priority for the filingdate of, commonly owned, co-pending U.S. patent application Ser. No.15/891,890. “Mapping Fracture Length Using Downhole Ground PenetratingRadar,” filed on Feb. 8, 2018.

The present application is also related to commonly owned U.S. patentapplication Ser. No. 16/394,741, filed of even date herewith, entitled“Apparatus For Mapping Fracture Length Using Downhole Ground PenetratingRadar,” and having the same inventor as the present application.

BACKGROUND OF THE INVENTION 1. Field of the Invention

The present invention relates to geophysical exploration, and moreparticularly to mapping the length of fractures in subsurface reservoirsbased on measures obtained from ground penetrating radar systems locatedin well boreholes in areas of interest.

2. Description of the Related Art

Unconventional reservoirs are becoming an increasingly important sourceof oil and gas for the world. Unconventional reservoirs are those thatrequire special recovery operations outside the conventional operatingpractices. Unconventional reservoirs may be of several types. Amongthese several types are reservoirs those containing what are known astight-gas sands, and also reservoirs containing gas and oil shales. Oneof the challenges to develop gas and oil shale reservoirs is their lowformation permeability. Current strategy to produce these reservoirs isby inducing hydraulic fractures to increase permeability and achieveeconomic production rates. It is therefore important to be able tocharacterize fracture length and orientation.

There have been several methods used for characterizing fracture lengthand orientation. A method known as microseismic monitoring is a methodwhich has been most often used. Microseismic monitoring relied onacoustic events that occurred when the formation rock was beingfractured. Typically, microseismic monitoring sensors had to be placedat the surface, or in nearby wells, because the acoustic environment inthe wellbore of the fracture well which was being stimulated was toonoisy. Aside from acoustic environmental noise, other considerationsthat determined the success of a microseismic survey included:seismogenic potential, which was dependent mainly on the properties ofthe formation; and detection capability, which was dependent on thesensors used and on parameters which affected signal propagation.

Microseismic surveys required nearby monitoring wells (typically withinhundreds of meters) for the monitoring to be performed. Otherwise, thedata could only be collected at the surface when the formation wasrelatively shallow (˜10.000 ft.). For deeper formations and in theabsence of nearby wells, microseismic surveys were of minimal value.This was due to the fact that the microseismic signal resulting fromfracturing was attenuated along its path to the surface. The result wasthat the microseismic signal was not distinguishable from the acousticenvironment noise.

Other problems with microseismic monitoring included, among others,uncertainty in the velocity model; microseismic signal frequencieshigher than 200 Hz were hard to achieve; raypath polarizations; anduncertainties in arrival times of the observed input data. The foregoingproblems and limitations, together with the high costs associated withthe operation posed a significant limitation to the deployment of themicroseismic monitoring on a large scale.

So far as is known, other fracture characterization methods also haddisadvantages. The disadvantages were in general one or more of thefollowing: being limited in effectiveness to shallow reservoirs;involving complex data interpretation processes; requiring that nearbymonitoring wells be present; and being affected by environmentalacoustic noise.

More specifically, fracture characterization for investigating fracturelength by pseudo three dimensional (P3D) fracture propagation models didnot measure fracture length, but rather formed estimates with valueswhich varied greatly depending on the model used. Well testing toinvestigate fracture length also produced results which varied based onstarting assumptions, and well test data prior to fracturing was oftennot available. Tiltmeters for investigating fracture length wereexpensive, difficult to operate and difficult to interpret.

Fracture characterization for investigating fracture height with pseudothree dimensional fracture propagation models and with tiltmeters hadlike disadvantages to those when investigating fracture length.Temperature and tracer logging to investigate fracture height werelimited by shallow depths of penetration, providing results only nearthe wellbore of the fracture well. Temperature logs were also difficultto interpret in the field. Stress profiling to investigate fractureheight required in-situ stress tests for calibration, and did notdirectly measure the fracture.

Fracture azimuth characterization with pseudo three dimensional fracturepropagation models and with tiltmeters had like disadvantages to thosewhen investigating fracture length or height. Core techniques forfracture azimuth characterization were expensive due to costs ofobtaining core samples, and multiple tests were required for accuracy.Log techniques for fracture azimuth characterization required thepresence of natural fractures and that open hole logs be available fromthe fracture well.

SUMMARY OF THE INVENTION

Briefly, the present invention provides a new and improved method ofdetermining location of end portions of a fracture in a subsurfaceformation penetrated by a well. Electromagnetic energy is emitted from aground penetrating radar transmitter in the well at a depth of interest.The ground penetrating radar electromagnetic energy is sensed afteremission with a radar receiver in the well at a distance from the groundpenetrating radar transmitter. The time of receipt of the groundpenetrating radar electromagnetic energy by the radar receiver issensed. From the arrival time of the received electromagnetic energy,the location of end portions of the fracture in the subsurface formationis then determined.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram, partly in cross-section, of a groundpenetrating radar system according to the present invention deployed ina subsurface formation penetrated by a horizontal wellbore.

FIG. 2 is a schematic diagram of fracture length determination accordingto the present invention with the ground penetrating radar system ofFIG. 1.

FIG. 3 is schematic diagram of a laboratory model used in test mappingof fracture length with a ground penetrating radar system according tothe present invention.

FIGS. 4, 5, 6, 7, 8 and 9 are plots of received radar signals asfunctions of time obtained according to the present invention duringtesting of the laboratory model of FIG. 3.

FIGS. 10A, 10B, 11A, 11B, 12A and 12B are comparative plots of mappedfractures of different lengths obtained according to the presentinvention during testing of the laboratory model of FIG. 3 for differentground penetrating radar frequencies.

FIGS. 13A, 13B and 13C are comparative plots of mapped fracturesobtained according to the present invention during testing of thelaboratory model of FIG. 3 with different reservoir conductivities.

FIG. 14 is a schematic diagram of the data processing system of theground penetrating radar system of FIG. 1.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

According to the present invention, a method is provided to mappingfracture length with downhole ground penetrating radar waves thateliminates the need for nearby monitoring wells and surface sensors. Thepresent invention takes advantage of what is known in physics as theknife-edge effect. The knife-edge effect is based on the Huygens-Fresnelprinciple, which is that a well-defined obstruction to anelectromagnetic wave acts as a secondary source of an electromagneticwave. The obstruction acting as a secondary source creates a newelectromagnetic wavefront appearing to emanate from the obstruction.

In the drawings, a ground penetrating radar well logging L is shown inFIG. 1. The ground penetrating radar well logging L includes a downholeground penetrating radar Tx which emits when activated a pulse ofelectromagnetic wave energy that travels into the earth formation. Aportion of the emitted pulse of electromagnetic wave energy travelsdirectly from the transmitter Tx to the receiver Rx and is detected as afirst break pulse having a first travel time. When there is a fracture20 present in a subsurface formation in which the well logging tool ispresent, a portion of the emitted pulse of electromagnetic wave energyis diffracted by a tip 22 of fracture 20. The diffracted signal is thensensed by one or more downhole receiver(s) Rx. Length of the fracture 20or distance to the tip 22 is then determined, as will be explained, fromthe travel time of the diffracted ground penetrating radarelectromagnetic pulse sensed at the receiver(s) Rx.

The well logging tool L includes a sonde or housing body 30 which issuspended for movement in a wellbore 32 for movement by a wirelinelogging cable 34. The well logging tool T is moved in the wellbore 32 towell depths of interest in a formation 36 which is of interest forcharacterization of the length of fracture 20. As shown in FIG. 1, thewellbore 32 for an oil or gas shale formation 36 of an unconventionalreservoir has transitioned from vertical near the earth surface to agenerally horizontal plane by directional drilling.

Measures of travel time of the diffracted ground penetrating radarelectromagnetic pulse sensed at the receiver(s) Rx of the downholelogging tool L are telemetered by a downhole telemetry system 38 in thedownhole sonde 30 over the wireline logging cable 34 to an upholetelemetry and data processing system D (FIGS. 1 and 14). Travel timemeasurements from the logging tool are received by the uphole telemetryand data processing system D in a data input unit 42 as functions ofborehole depth or length of extent in wellbore 32.

A preprocessing unit 44 and a processor computer 46 receive and processthe measures of travel time of the diffracted ground penetrating radarelectromagnetic pulses so that length of the fracture 20 presentadjacent the wellbore 32 at a depth of interest may be determined. Thedetermined fracture lengths at depths of interest are then stored orrecorded in memory 48 and displayed by action of a display 50 in thedesired manner, which is usually a plot of the parameters of interest asa function of depth at which they are determined within the wellbore 32.

A surface depth measurement system, such as a depth measure sheave wheel52 and associated circuitry is provided to indicate depth of the loggingtool L in the wellbore 32. The travel time data from the downholesubassembly 10 are recorded as functions of borehole depth in the datamemory 48. Once recorded, the travel time measurements are transferredas needed into the preprocessing unit 44 and processor computer 46 ofthe data processing system D. The travel time measurements are aftertransfer subjected to conventional preprocessing in the preprocessingunit 44 and then transferred to computer 46. The processed datameasurements in computer 46 are then available for processing todetermine fracture length of fractures such as shown at 20 according tothe present invention in a manner to be set forth below.

A series of numerical simulations were performed to demonstratecapabilities of the present invention. A numerical two-dimensional or2-D model (FIGS. 2 and 3) was created representing a section of anunconventional reservoir), with a section of horizontal wellbore 60 anda fracture 62 that is perpendicular (FIG. 2) to the wellbore 60. Thelength of the fracture 62 to a tip 64 was configured in the numericalmodel to be variable to confirm the sensitivity of the present inventionto the fracture length. A location 66 for transmitter Tx and a location68 for receiver Rx were configured in the numerical model to be locatedinside the wellbore 60, spaced equidistant on either side of thefracture 62. The positions 66 and 68 of transmitter Tx and receiver Rxwere moved for several different simulation scenarios to determine theeffect of transmitter and receiver position on the received groundpenetrating radar electromagnetic pulse signal.

In an initial test scenario (FIG. 3) for the numerical model, a 1 cmwide and 5 m long fracture 62 was simulated. The fracture was mappedaccording to the present invention using a 2 GHz electromagnetic pulse.The transmitter Tx location 66 and the receiver location 68 in thenumerical model were 10 m apart from each other. Values for subsurfaceformation electromagnetic field parameters ε_(r), σ, and μ_(r) in thenumerical model are indicated in FIG. 3. An electromagnetic pulse wasthen generated at by numerical modeling at location 66 and itspropagation was monitored in the numerical model.

The received signal from numerical modeling is shown as a plot 70 inFIG. 4. The received signal plot 70 clearly indicates two signal breaks,a first signal break 72 at ˜129 nanoseconds (ns) and a second break 74at ˜180 ns. The time when the first break 72 occurs correlates with thedistance in the numerical model between transmitter location 66 andreceiver location 68 (˜10 m in this case), while the second break 74correlates with the length of the path an emitted ground penetratingradar electromagnetic pulse would travel if it was being diffracted by afracture tip as if it were a secondary behaving as described above withregard to FIG. 2.

To confirm that the second break travel time corresponds to the fracturelength, second and third numerical modeling scenarios were simulatedwith fracture 62 having lengths of 10 m and 15 m, respectively. Thereceived second breaks 76 (FIG. 5) and 78 (FIG. 6) show that as fracturelength increases, the time at which the second break occurs becomesgreater (FIGS. 5 and 6). Further, the indications of travel time bysecond breaks 76 and 78 are in agreement with what it would be if thepulse was propagating as a result of secondary electromagnetic waves asillustrated schematically in FIG. 2. The results in FIGS. 4, 5 and 6 ofnumerical modeling simulations suggest that the fracture tip 62 isindeed acting as a secondary electromagnetic source. These resultsconfirm that there is a relationship between the length of the fractureand the time at which the second break of the emitted ground penetratingradar electromagnetic wave pulse occurs.

To investigate whether the present invention methodology is sensitive atlower frequencies, the numerical modeling scenario for a 10 m longfracture was repeated but this time the pulse was centered at 100 MHz,rather than 2 GHz. Results are plotted in FIG. 7. The received signalclearly shows a first break 80 corresponding to the distance betweentransmitter and receiver, and a second break 82 related to the fracturelength. A notable difference between using 2 GHz and 100 MHz, aside fromthe amplitude, is the lack of ringing in the 100 MHz signal. This isapparently explained by the fact that at 2 GHz the ground penetratingradar signal can in effect penetrate or see inside the fracture, whileat 100 MHz the ground penetrating radar signal cannot penetrate or seeinside the fracture because the wavelength at the lower 100 MHzfrequency is not small enough. In both cases, however, the presentinvention is capable to determine the fracture length with groundpenetrating radar.

A summary of the results obtained by numerical modeling and plotted inFIGS. 4, 5, 6 and 7 is contained in Table 1.

TABLE 1 Fracture Path length Frequency Direct length CalculatedSimulation (m) (GHz) shot (ns) (m) time (ns) time (ns) 5 2 129 14.1 180~180 10 2 129 22.4 290 ~290 10 0.1 129 22.4 290 ~290 15 2 129 31.6 410~410

Table 1 above shows that second breaks from these simulations are inaccord with the time a second break should occur if indeed the tip ofthe fracture is acting as a secondary source. This indicates that thepresent invention can be used to estimate the length of a fracture thatis perpendicular to the wellbore.

To demonstrate of the present invention, a further set of numericalsimulations were performed. In the numerical simulations, thetransmitter position 66 and receiver position 68 were located atdifferent spacings from each other in the wellbore for a fixed fracturelength (10 m) and with a 2 GHz ground penetrating radar pulse emitted.Initially, results were obtained with the transmitter position 66 andreceiver position 68 located 10 m apart from each other in the numericalmodel, which is the configuration for the modeling depicted in FIG. 7.The results of numerical modeling of 10 m spacing are shown in thetravel times displayed in FIG. 5.

For the second and third scenario of the further set, both thetransmitter position 66 and receiver position 68 were moved closer tothe fracture 60. First the transmitter position 66 and receiver position68 were placed 3 m away from the fracture 60 on either side. The resultsof numerical modeling for 6 m spacing between the transmitter position66 and receiver position 68 are shown in the travel times displayed inFIG. 8. The transmitter position 66 and receiver position 68 were thenmoved to 1 m away from the fracture 60 on either side. The results ofnumerical modeling of 2 m spacing between the transmitter position 66and receiver position 68 are shown in the travel times displayed in FIG.9. The received signals plotted in FIGS. 8 and 9 again show that thetime when the second breaks 84 (FIG. 8) and 86 (FIG. 9) occur correlateswith the length of the path the signal would have to travel if thefracture tip 64 is acting as a secondary source.

Table 2 presents a summary of the results obtained in the further set ofsimulations.

TABLE 2 Distance Fracture Fre- between Direct Path length quency Tx-shot length Calculated Simulation (m) (MHz) Rx (m) (ns) (m) time (ns)time (ns) 10 100 10 129 22.4 290 ~290 10 100 6 77 20.9 270 ~270 10 100 226 20.1 260 ~260

The numerical modeling results plotted in FIGS. 7, 8 and 9 andsummarized in Table 2 indicate that the present invention is sensitiveto spacing of ground penetrating radar transmitter and receiver positionfrom the fracture.

Next, further numerical modeling simulations were performed to study theeffect of ground penetrating radar frequency on the ability to mapfractures with different lengths. Fractures with three different lengths(5 m, 10 m, and 15 m) were simulated and surveyed using 10 MHz and 100MHz pulses for each of three different fracture lengths.

FIGS. 10A, 11A and 12A are plots of the numerical modeling of fracturesmapped with ground penetrating radar emitting a pulse at 20 MHz andfracture lengths of 5 m, 10 m and 15 m, respectively. FIGS. 10B, 11B and12B are plots of the numerical modeling of fractures mapped with groundpenetrating radar emitting a pulse at 100 MHz and fracture lengths of 5m, 10 m and 15 m, respectively.

The numerical modeling results plotted in FIGS. 10A through 12B showthat the lower the ground penetrating radar frequency, the longer thefracture needs to be to be able to properly map its length. While lowerground penetrating radar frequencies offer increased penetration, atradeoff between penetration and ability to map a fracture's lengthexists.

Additionally, the effect of the conductivity of the reservoir in thereceived signal was analyzed. FIGS. 13A, 13B and 13C are plots ofnumerical models of received ground penetrating radar pulses as afunction of time for a fracture having a length of 10 m. FIG. 13A isplot of a received signal with reservoir conductivity assumed to have azero value. FIG. 13B is plot of a received signal with a reservoirconductivity having a value of 0.003 S/m, or Siemens per meter. FIG. 13Cis plot of a received signal with a reservoir conductivity having avalue of 0.03 S/m. FIGS. 13A through 13C confirm that higherconductivity in a reservoir formation results in increased attenuationof the ground penetrating radar waves. Therefore the present inventionis more preferably suited mapping fractures in low conductivityreservoir formation environments.

The present invention with ground penetrating radar electromagneticwaves offers advantages in contrast to prior seismic waves to mapfractures, in addition to electromagnetic waves and seismic waves beingdifferent types of wave energy. The present invention does not requiremonitoring wells in proximity to the wellbore (typically within hundredsof meters for microseismic monitoring). The present invention is alsoless complicated because it does not require a receiver array at thesurface, and the data is less complex to interpret. The presentinvention can be used for deep reservoirs as opposed to microseismicmonitoring. As has been mentioned, microseismic monitoring is limited toshallow reservoirs (typically no deeper than 3 km) due to signalattenuation. The present invention is also not affected by acousticnoise. It can be seen that the present invention provides an improvedmethod to map hydraulic fractures.

The invention has been sufficiently described so that a person withaverage knowledge in the field of reservoir modeling and simulation mayreproduce and obtain the results mentioned herein described for theinvention. Nonetheless, any skilled person in the field of technique,subject of the invention herein, may carry out modifications notdescribed in the request herein, to apply these modifications to adetermined structure and methodology, or in the use and practicethereof, requires the claimed matter in the following claims; suchstructures and processes shall be covered within the scope of theinvention.

It should be noted and understood that there can be improvements andmodifications made of the present invention described in detail abovewithout departing from the spirit or scope of the invention as set forthin the accompanying claims.

What is claimed is:
 1. A data processing system for determining locationof end portions of a fracture in a subsurface formation penetrated by awell, comprising: (a) an uphole telemetry system receiving, from a welllogging tool in the well, an uphole signal comprising measures of sensedtime of receipt of diffracted ground penetrating radar electromagneticenergy sensed by a radar receiver in the well logging tool afteremission of electromagnetic energy by a ground penetrating radarelectromagnetic energy transmitter in the well logging tool; (b) theuphole telemetry system further receiving, from the uphole signal,sensed arrival of a first break pulse indicating spacing of the radartransmitter and radar receiver, and sensed arrival of a second breakpulse indicating presence of a fracture as a secondary electromagneticenergy source; and (c) a processor computer processing the receiveduphole signal to determine, from the measures of the sensed time ofreceipt of the sensed electromagnetic energy, the location of endportions of the fracture in the subsurface formation.
 2. The dataprocessing system of claim 1, wherein the processor computer furtherdetermines the location of end portions of the fracture by determiningthe location of end portions of the fracture from an arrival time of thesecond break pulse.
 3. The data processing system of claim 1 wherein thefracture in the formation is formed by fracturing the subsurfaceformation.
 4. The data processing system of claim 1 wherein the well isformed by horizontal drilling of the subsurface formation.
 5. The dataprocessing system of claim 1 further including: a memory storing thedetermined location of end portions of the fracture in the subsurfaceformation.
 6. The data processing system of claim 1 further including:an output display forming an image of the determined location of endportions of the fracture in the subsurface formation.